Composition for enhanced hydrocarbon recovery from a formation

ABSTRACT

A hydrocarbon recovery composition which comprises a first blend of C24-28 internal olefin sulfonates and an injectable fluid composition comprising the hydrocarbon recovery composition, water and/or brine wherein the hydrocarbon recovery composition is present in an amount of from 0.05 to 1.0 wt % of the total injectable fluid composition can be used for enhanced hydrocarbon recovery from a formation.

PRIORITY CLAIM

The present application is a divisional of U.S. Non-provisional Ser. No.13/382,387, filed Jan. 5, 2012, which is a National Stage (§371) ofInternational Application No. PCT/US2010/041044, filed Jul. 6, 2010,which claims the benefit of U.S. Provisional No. 61/303,962, filed Feb.12, 2010 and U.S. Provisional No. 61/224,321, filed Jul. 9, 2009,incorporated herein by reference.

FIELD OF THE INVENTION

The present invention generally relates to methods for recovery ofhydrocarbons from hydrocarbon-bearing formations. More particularly,embodiments described herein relate to methods of enhanced hydrocarbonrecovery and to compositions useful therein which are specificallydesigned for use in hydrocarbon-bearing formations wherein thehydrocarbon to be recovered is crude oil which contains a significantamount of specific solubility groups and chemical families.

BACKGROUND OF THE INVENTION

Hydrocarbons may be recovered from hydrocarbon-bearing formations bypenetrating the formation with one or more wells through which thehydrocarbons may flow to the surface. Conditions (e.g., permeability,hydrocarbon concentration, porosity, temperature, pressure, waterproduction rates, amongst others) of the formation may affect theeconomic viability of hydrocarbon production from thehydrocarbon-bearing formation. A hydrocarbon-bearing formation may havenatural energy (e.g., gas, water) to aid in mobilizing hydrocarbons tothe surface of the hydrocarbon-bearing formation. Natural energy may bein the form of water. Water may exert pressure to mobilize hydrocarbonsto one or more production wells. Gas may be present in thehydrocarbon-bearing formation (reservoir) at sufficient pressures tomobilize hydrocarbons to one or more production wells. The naturalenergy source may become depleted over time.

Supplemental recovery processes may be used to continue recovery ofhydrocarbons from the hydrocarbon containing formation. Examples ofsupplemental processes include waterflooding, polymer flooding, alkaliflooding, thermal processes, solution flooding or combinations thereof.

In chemical enhanced oil recovery (EOR) the mobilization of residual oilsaturation is achieved through surfactants which generate a sufficiently(ultra) low crude oil/water interfacial tension (IFT) to give acapillary number large enough to overcome capillary forces and allow theoil to flow (I. Chatzis and N. R. Morrows, “Correlation of capillarynumber relationship for sandstone”. SPE Journal, Vol 29, pp 555-562,1989). However, reservoirs have different characteristics (crude oiltype and composition, temperature and the water composition—salinity,cation distribution, hardness) and it is desirable that the structuresof added surfactant(s) be matched to these conditions to achieve a lowIFT. In addition, a promising surfactant must fulfill other importantcriteria including low rock retention, compatibility with polymer,thermal and hydrolytic stability and acceptable cost.

Compositions and methods for enhanced hydrocarbon recovery utilizing analpha olefin sulfate-containing surfactant component are known. U.S.Pat. Nos. 4,488,976 and 4,537,253 describe enhanced oil or recoverycompositions containing such chemicals. Compositions and methods forenhanced hydrocarbons recovery utilizing internal olefin sulfonates arealso known. Such a surfactant composition is described in U.S. Pat. No.4,597,879. The compositions described in the foregoing patents have thedisadvantages that brine solubility and divalent ion tolerance areinsufficient at certain reservoir conditions, which render the productsunsuitable for said hydrocarbon-bearing formations.

U.S. Pat. No. 4,979,564 describes the use of internal olefin sulfonatesin a method for enhanced oil recovery using low tension viscouswaterflood. An example of a commercially available material described asbeing useful was ENORDET Internal Olefin Sulfonate, IOS 1720, a productof Shell Oil Company identified as a sulfonated C₁₇₋₂₀ internal olefinsodium salt. This material has a low degree of branching. U.S. Pat. No.5,068,043 describes a petroleum acid soap-containing surfactant systemfor waterflooding wherein a cosurfactant comprising a C₁₇₋₂₀ or a C₂₀₋₂₄internal olefin sulfonate was used. In “Field Test ofCosurfactant-enhanced Alkaline Flooding” by Falls et al., Society ofPetroleum Engineers Reservoir Engineering, 1994, the authors describethe use of a C₁₇₋₂₀ or a C₂₀₋₂₄ internal olefin sulfonate in awaterflooding composition with an alcohol alkoxylate surfactant to keepthe composition as a single phase at ambient temperature withoutsignificantly affecting performance at reservoir temperature. In theabove-mentioned reference, the reservoir water had a salinity of about0.4 wt % sodium chloride. There is also industry experience with the useof certain alcohol alkoxysulfate surfactants. These materials, usedindividually, also have disadvantages under very severe conditions ofsalinity, hardness and temperature, in part because certain alcoholalkoxysulfate surfactants are not stable at high temperature, i.e.,above about 70° C.

A crude oil (including any generic low API heavy crude oils and/or highAPI light crude oils) may contain significant amounts of specificsolubility groups and chemical families. The overall distribution ofboth solubility groups and chemical families is a direct result ofgeochemical processes. The recovery of crude oil containing suchcomponents using surfactant flooding presents some unique problems. Suchspecific solubility groups include saturates, aromatics, asphaltenes andresins. Some of these solubility groups are natural surfactants presentin the crude oil. These are polar fractions which under particularconditions may be surface-active and may adversely affect crude oilphase behavior during production operations. Moreover, solubility groupsmay also contain paraffins, naphthenic acids and basic components. Someof these specific chemical families are known to contribute towardsemulsion stabilization under production conditions of oilfield fluids.For naphthenic acids, surface-activity is also a function of pH value.Naphthenic acids and their particular phase behavior may thereforeinterfere with the desired performance of a surfactant EOR chemical.Crude oils are normally classified using API gravity but this number maymask many of the more detailed characteristics of fluid phase behavior.An understanding of phase behavior, and thus more detailed prediction ofchemical EOR may only be achieved by investigating crude oilcompositions in more detail (e.g. solubility groups as well as specificchemical families). It appears that conventional surfactants do notprovide the desired benefits for certain crude oils. For instance, eveninternal olefin sulfonates containing up to 20-24 carbons are notsufficiently effective for this commercial use. This may be due tocompeting solubilization effects of the many components of crude oils inhydrocarbon-bearing formations.

SUMMARY OF THE INVENTION

In an embodiment, hydrocarbons may be produced from ahydrocarbon-bearing formation containing crude oil containingsignificant amounts of specific solubility groups and chemical familiesby a method that includes treating at least a portion of thehydrocarbon-bearing formation with a hydrocarbon recovery compositionwhich is comprised of a particular very high molecular weight internalolefin sulfonate. This material is effective over a salinity range ofabout 1% by weight or lower to about 10% by weight or higher and over atemperature range of from about 40 to 140° C.

The present invention provides a method of treating these crudeoil-bearing formations which contain significant amounts of specificsolubility groups and chemical families which comprises (a) providing ahydrocarbon recovery composition to at least a portion of a crude oilcontaining formation, wherein the composition comprises a C₂₄₋₂₈internal olefin sulfonate (IOS); and (b) allowing the composition tointeract with hydrocarbons and other components in the hydrocarboncontaining formation. C₁₅₋₁₈ internal olefin sulfonates, C₁₉₋₂₃ internalolefin sulfonates, C₂₀₋₂₄ internal olefin sulfonates and mixturesthereof may be blended with the C₂₄₋₂₈ internal olefin sulfonate toenhance its microemulsion behavior. The weight ratio of the C₂₄₋₂₈internal olefin sulfonate to the other IOS may be from about 10:90 toabout 90:10. Preferably the C₂₄₋₂₈ internal olefin sulfonate comprisesat least about 50% of the IOS blend.

In an embodiment, the hydrocarbon recovery composition may comprise fromabout 1 to about 75 wt % of the C₂₄₋₂₈ internal olefin sulfonate orblend containing it, preferably from about 10 to about 40 wt % and morepreferably from about 20 to about 30 wt %. In an embodiment, ahydrocarbon composition may be produced from a hydrocarbon-bearingformation. The hydrocarbon composition may include any combination ofhydrocarbons, the internal olefin sulfonate described above, asolubilizing agent, associated gas, water, solubility groups(asphaltenes, resins, saturates, aromatics), specific chemical families(naphthenic acids).

In an embodiment, the hydrocarbon recovery composition is provided tothe hydrocarbon-bearing formation by admixing it with water and/or brinefrom the formation. Preferably, the hydrocarbon recovery compositioncomprises from about 0.01 to about 2.0 wt % of the total water and/orbrine/hydrocarbon recovery composition mixture (the injectable fluid).More important is the amount of actual active matter that is present inthe injectable fluid (active matter is the surfactant, here the C₂₄₋₂₈internal olefin sulfonate or blend containing it). Thus, the amount ofthe internal olefin sulfonate in the injectable fluid may be from about0.05 to about 1.0 wt %, preferably from about 0.1 to about 0.8 wt %. Theinjectable fluid is then injected into the hydrocarbon-bearingformation.

In an embodiment, a hydrocarbon composition may be produced from ahydrocarbon containing formation. The hydrocarbon containing thecomposition may include any combination of hydrocarbons, internal olefinsulfonate, associated gas, water, solubility groups (asphaltenes,resins, saturates, aromatics), specific chemical families (naphthenicacids, basic nitrogen compounds).

The present invention also provides a method of injecting a hydrocarbonrecovery composition comprising a C₂₄₋₂₈ internal olefin sulfonate intoa hydrocarbon containing formation which comprises:

(a) making a solubilized C₂₄₋₂₈ internal olefin sulfonate (IOS)hydrocarbon recovery composition fluid by mixing a major portion of aC₂₄₋₂₈ internal olefin sulfonate in fresh water or water having a brinesalinity of less than about 2 wt % at a temperature of 50° C. or lowerand adding to the mixture a minor portion of a solubilizer whichcomprises a C₁₅₋₁₈ internal olefin sulfonate or a C₁₉₋₂₃ internal olefinsulfonate or mixtures thereof, wherein the weight ratio of thesolubilizer to the C₂₄₋₂₈ internal olefin sulfonate may be from about10:90 to about 90:10; and

(b) injecting the solubilized C₂₄₋₂₈ internal olefin sulfonatehydrocarbon recovery composition into the hydrocarbon containingformation.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 depicts an embodiment of treating a hydrocarbon-bearingformation;

FIG. 2 depicts an embodiment of treating a hydrocarbon-bearingformation.

FIG. 3 depicts the effect of crude oil solubility fractions on IOSperformance

While the invention is susceptible to various modifications andalternative forms, specific embodiments thereof are shown by way ofexample in the drawings and will herein be described in detail. Itshould be understood that the drawing and detailed description theretoare not intended to limit the invention to the particular formdisclosed, but on the contrary, the intention is to cover allmodifications, equivalents and alternatives falling within the spiritand scope of the present invention as defined by the appended claims.

DETAILED DESCRIPTION OF EMBODIMENTS

“Average carbon number” as used herein is determined by multiplying thenumber of carbon atoms of each internal olefin sulfonate in the mixtureof internal olefin sulfonates by the mole percent of that internalolefin sulfonate and then adding the products.

“C₁₅₋₁₈ internal olefin sulfonate” as used herein means a mixture ofinternal olefin sulfonates wherein the mixture has an average carbonnumber of from about 16 to about 17 and at least 50% by weight,preferably at least 75% by weight, most preferably at least 90% byweight, of the internal olefin sulfonates in the mixture contain from 15to 18 carbon atoms.

“C₁₉₋₂₃ internal olefin sulfonate” as used herein means a mixture ofinternal olefin sulfonates wherein the mixture has an average carbonnumber of from about 21 to about 23 and at least 50% by weight,preferably at least 60% by weight, of the internal olefin sulfonates inthe mixture contain from 19 to 23 carbon atoms.

“C₂₀₋₂₄ internal olefin sulfonate” as used herein means a mixture ofinternal olefin sulfonates wherein the mixture has an average carbonnumber of from about 20.5 to about 23 and at least 50% by weight,preferably at least 65% by weight, most preferably at least 75% byweight, of the internal olefin sulfonates in the mixture contain from 20to 24 carbon atoms.

“C₂₄₋₂₈ internal olefin sulfonate” as used herein means a blend ofinternal olefin sulfonates wherein the blend has an average carbonnumber of from 24.5 to 27 and at least 40% by weight, preferably atleast 50% by weight, most preferably at least 60% by weight, of theinternal olefin sulfonates in the blend contain from 24 to 28 carbonatoms.

The term “crude oil with specific solubility groups and chemicalfamilies” as used herein means crude oil which has an asphaltenes toresin weight ratio of at most about 0.5, a saturates to aromatics weightratio of at most about 0.7 and a naphthenic acid concentration of atmost about 1900 ppm. The crude oil may have an asphaltenes to resinweight ratio of from 0.1 to 0.5. The crude oil may have a saturates toaromatic weight ratio of from 0.1 to 0.7. The crude oil may have anaphthenic acid concentration of from 100 ppmw to 1900 ppmw. The crudeoil may have an API ranging from low (<20) to high (>40). Crude oilgenerally contains measurable quantities of solubility groups such as:asphaltenes, resins, saturates, aromatics. These can be easily measuredusing conventional oilfield chemistry methods. Crude oil also maycontain specific chemical families such as: naphthenic acids and basicnitrogen compounds. These may be measured using conventional andspecialized oilfield chemistry methods.

“Asphaltenes” as used herein means the fraction or solubility group ofcrude oil that is a) insoluble in light alkanes such as n-pentane orn-hexane and b) soluble in aromatic solvents such as toluene andbenzene. Asphaltenes are not a specific family of chemicals with commonfunctionality and varying molecular weight. They are a continuum ofmaterial—generally at the high end in molecular weight, polarity andaromaticity—some of which may separate as an additional solid phase inresponse to changes in pressure, composition, and/or temperature.Asphaltenes may comprise polycyclic aromatic clusters substituted withvarying alkyl side chains with metal species and the molecular weightmay be in the 500-2000 g/mole range.

“Resins” as used herein means the fraction or solubility group of crudeoil that is soluble in higher molecular weight normal alkanes such asn-heptane and insoluble in lower molecular weight alkanes such aspropane.

“Aromatics” as used herein refers to the fraction or solubility group ofbenzene and its structural derivatives, the majority of which maycontain alkyl chains and cycloalkane rings, along with additionalaromatic rings.

“Saturates” as used herein refers to the fraction of solubility groupwhere every carbon atom is attached to two hydrogen atoms, except thoseat the ends of the chain, which bear three hydrogen atoms, for instancealkanes.

“Naphthenic acids” are used herein means all carboxylic acid containingcrude oil components, including for instance fatty acids. Theserepresent a specific chemical family.

Crude oil is often characterized by conventional SARA separation ofsolubility groups (saturates, aromatic, resins, asphaltenes). First, theasphaltenes are separated by precipitation by alkanes. The remainingsoluble components are then separated by high performance liquidchromatography or column chromatography. Specific chemical families suchas naphthenic acids and basic nitrogen compounds must be identifiedusing conventional and specialized detailed analytical techniques, suchas potentiometric titrations, infrared spectroscopy and massspectrometry.

Hydrocarbons may be produced from hydrocarbon-bearing formations throughwells penetrating a hydrocarbon containing formation. “Hydrocarbons” aregenerally defined as molecules formed primarily of carbon and hydrogenatoms such as oil and natural gas. Hydrocarbons may also include otherelements, such as, but not limited to, halogens, metallic elements,nitrogen, oxygen and/or sulfur. Hydrocarbons derived from a hydrocarbonformation may include, but are not limited to, asphaltenes, resins,saturates, aromatics or combinations thereof. Hydrocarbons may belocated within or adjacent to mineral matrices within the earth.Matrices may include, but are not limited to, sedimentary rock, sands,silicilytes, carbonates, diatomites and other porous media.

A “formation” includes one or more hydrocarbon containing layers, one ormore non-hydrocarbon layers, an overburden and/or an underburden. An“overburden” and/or an “underburden” includes one or more differenttypes of impermeable materials. For example, overburden/underburden mayinclude rock, shale, mudstone, or wet/tight carbonate (i.e., animpermeable carbonate without hydrocarbons). For example, an underburdenmay contain shale or mudstone. In some cases, the overburden/underburdenmay be somewhat permeable. For example, an underburden may be composedof a permeable mineral such as sandstone or limestone. In someembodiments, at least a portion of a hydrocarbon-bearing formation mayexist at less than or more than 1000 feet below the earth's surface.

Properties of a hydrocarbon-bearing formation may affect howhydrocarbons flow through an underburden/overburden to one or moreproduction wells. Properties include, but are not limited to,mineralogy, porosity, permeability, pore size distribution, surfacearea, salinity and temperature of the formation. Overburden/underburdenproperties in combination with hydrocarbon properties, such as,capillary pressure (static) characteristics and relative permeability(flow) characteristics may affect mobilization of hydrocarbons throughthe hydrocarbon containing formation.

Permeability of a hydrocarbon-bearing formation may vary depending onthe formation composition. A relatively permeable formation may includeheavy hydrocarbons entrained in, for example, sand or carbonate.“Relatively permeable,” as used herein, refers to formations or portionsthereof, that have an average permeability of 10 millidarcy or more.“Relatively low permeability” as used herein, refers to formations orportions thereof that have an average permeability of less than about 10millidarcy. One darcy is equal to about 0.99 square micrometers. Animpermeable portion of a formation generally has a permeability of lessthan about 0.1 millidarcy. In some cases, a portion or all of ahydrocarbon of a relatively permeable formation may includepredominantly heavy hydrocarbons and/or tar with no supporting mineralgrain framework and only floating (or no) mineral matter (e.g., asphaltlakes).

Fluids (e.g., gas, water, hydrocarbons or combinations thereof) ofdifferent densities may exist in a hydrocarbon-bearing formation. Amixture of fluids in the hydrocarbon-bearing formation may form layersbetween an underburden and an overburden according to fluid density. Gasmay form a top layer, hydrocarbons may form a middle layer and water mayform a bottom layer in the hydrocarbon-bearing formation. The fluids maybe present in the hydrocarbon-bearing formation in various amounts.Interactions between the fluids in the formation may create interfacesor boundaries between the fluids. Interfaces or boundaries between thefluids and the formation may be created through interactions between thefluids and the formation. Typically, gases do not form boundaries withother fluids in a hydrocarbon containing formation. In an embodiment, afirst boundary may form between a water layer and underburden. A secondboundary may form between a water layer and a hydrocarbon layer. A thirdboundary may form between hydrocarbons of different densities in ahydrocarbon-bearing formation. Multiple fluids with multiple boundariesmay be present in a hydrocarbon-bearing formation, in some embodiments.It should be understood that many combinations of boundaries betweenfluids and between fluids and the overburden/underburden may be presentin a hydrocarbon-bearing formation.

Production of fluids may perturb the interaction between fluids andbetween fluids and the overburden/underburden. As fluids are removedfrom the hydrocarbon containing formation, the different fluid layersmay mix and form mixed fluid layers. The mixed fluids may have differentinteractions at the fluid boundaries. Depending on the interactions atthe boundaries of the mixed fluids, production of hydrocarbons maybecome difficult. Quantification of the interactions (e.g., energylevel) at the interface of the fluids and/or fluids andoverburden/underburden may be useful to predict mobilization ofhydrocarbons through the hydrocarbon-bearing formation.

Quantification of energy required for interactions (e.g., mixing)between fluids within a formation at an interface may be difficult tomeasure. Quantification of energy levels at an interface between fluidsmay be determined by generally known techniques (e.g., spinning droptensionmeter, Langmuir trough). Interaction energy requirements at aninterface may be referred to as interfacial tension. “Interfacialtension” as used herein, refers to a surface free energy that existsbetween two or more fluids that exhibit a boundary. A high interfacialtension value (e.g., greater than about 10 dynes/cm) may indicate theinability of one fluid to mix with a second fluid to form a fluidemulsion. As used herein, an “emulsion” refers to a dispersion of oneimmiscible fluid into a second fluid by addition of a composition thatreduces the interfacial tension between the fluids to achieve somedegree of stability. The inability of the fluids to mix may be due tohigh surface interaction energy between the two fluids or due to thepresence of solubility groups or specific chemical families Lowinterfacial tension values (e.g., less than about 1 dyne/cm) mayindicate less surface interaction between the two immiscible fluids.Less surface interaction energy between two immiscible fluids may resultin the mixing of the two fluids to form an emulsion. Fluids with lowinterfacial tension values may be mobilized to a well bore due toreduced capillary forces and subsequently produced from ahydrocarbon-bearing formation. Interfacial tension is also a function ofaqueous properties such as pH and cation content.

Fluids in a hydrocarbon-bearing formation may wet (e.g., adhere to anoverburden/underburden or spread onto an overburden/underburden in ahydrocarbon containing formation). As used herein, “wettability” refersto the preference of a fluid to spread on or adhere to a solid surfacein a formation in the presence of other fluids. Methods to determinewettability of a hydrocarbon formation are described by Craig, Jr. in“The Reservoir Engineering Aspects of Waterflooding”, 1971 MonographVolume 3, Society of Petroleum Engineers, which is herein incorporatedby reference. In an embodiment, hydrocarbons may adhere to sandstone inthe presence of gas or water. An overburden/underburden that issubstantially coated by hydrocarbons may be referred to as “oil wet.” Anoverburden/underburden may be oil wet due to the presence of polarand/or or surface-active components (e.g., asphaltenes) in thehydrocarbon-bearing formation. Formation composition (e.g., silica,carbonate or clay) may determine the amount of adsorption ofhydrocarbons on the surface of an overburden/underburden. In someembodiments, a porous and/or permeable formation may allow hydrocarbonsto more easily wet the overburden/underburden. A substantially oil wetoverburden/underburden may inhibit hydrocarbon production from thehydrocarbon-bearing formation. In certain embodiments, an oil wetportion of a hydrocarbon-bearing formation may be located at less thanor more than 1000 feet below the earth's surface.

A hydrocarbon formation may include water. Water may interact with thesurface of the underburden. As used herein, “water wet” refers to theformation of a coat of water on the surface of theoverburden/underburden. A water wet overburden/underburden may enhancehydrocarbon production from the formation by preventing hydrocarbonsfrom wetting the overburden/underburden. In certain embodiments, a waterwet portion of a hydrocarbon-bearing formation may include minor amountsof polar and/or or surface-active components.

Water in a hydrocarbon-bearing formation may contain minerals (e g,minerals containing barium, calcium, or magnesium) and mineral salts(e.g., sodium chloride, potassium chloride, magnesium chloride). Watersalinity, cation content, pH and/or water hardness in a formation mayaffect recovery of hydrocarbons in a hydrocarbon-bearing formation. Asused herein “salinity” refers to an amount of dissolved solids in water.“Water hardness,” as used herein, refers to a concentration of divalentions (e.g., calcium, magnesium) in the water. Water salinity andhardness may be determined by generally known methods (e.g.,conductivity, titration). As water salinity increases in ahydrocarbon-bearing formation, interfacial tensions between hydrocarbonsand water may be increased and the fluids may become more difficult toproduce. The interfacial tension is also a strong function of thedominant cation present in the water phase, pH and temperature.

A hydrocarbon-bearing formation may be selected for treatment based onfactors such as, but not limited to, thickness of hydrocarbon containinglayers within the formation, assessed liquid production content,location of the formation, salinity content of the formation,temperature of the formation, mineralogy and depth ofhydrocarbon-bearing layers. Initially, natural formation pressure andtemperature may be sufficient to cause hydrocarbons to flow into wellbores and out to the surface. Temperatures in a hydrocarbon containingformation may range from about 0° C. to about 300° C. The composition ofthe present invention is particularly advantageous when used at hightemperature because the internal olefin sulfonate is stable at suchtemperatures. As hydrocarbons are produced from a hydrocarbon-bearingformation, pressures and/or temperatures within the formation maydecline. Various forms of artificial lift (e.g., pumps, gas injection)and/or heating may be employed to continue to produce hydrocarbons fromthe hydrocarbon-bearing formation. Production of desired hydrocarbonsfrom the hydrocarbon-bearing formation may become uneconomical ashydrocarbons are depleted from the formation.

Mobilization of residual hydrocarbons retained in a hydrocarbon-bearingformation may be difficult due to viscosity of the hydrocarbons andcapillary effects of fluids in pores of the hydrocarbon-bearingformation. As used herein “capillary forces” refers to attractive forcesbetween fluids and at least a portion of the hydrocarbon-bearingcontaining formation. In an embodiment, capillary forces may be overcomeby increasing the pressures within a hydrocarbon-bearing formation. Inother embodiments, capillary forces may be overcome by reducing theinterfacial tension between fluids in a hydrocarbon-bearing formation.The ability to reduce the capillary forces in a hydrocarbon-bearingformation may depend on a number of factors, including, but not limitedto, the temperature of the hydrocarbon-bearing formation, the salinityand cationic composition of water in the hydrocarbon-bearing containingformation, and the precise composition of the hydrocarbon-bearingformation.

As production rates decrease, additional methods may be employed to makea hydrocarbon-bearing formation more economically viable. Methods mayinclude adding sources of water (e.g., brine, steam), gases (e.g.,carbon dioxide, nitrogen), alkaline fluids, polymers, monomers or anycombinations thereof to the hydrocarbon formation to increasemobilization of hydrocarbons.

In an embodiment, a hydrocarbon-bearing formation may be treated with aflood of water. A waterflood may include injecting water into a portionof a hydrocarbon-bearing formation through injections wells. Flooding ofat least a portion of the formation may water wet a portion of thehydrocarbon-bearing formation. The water wet portion of thehydrocarbon-bearing formation may be pressurized by known methods and awater/hydrocarbon mixture may be collected using one or more productionwells. The water layer, however, may not mix with the hydrocarbon layerefficiently. Poor mixing efficiency may be due to a high interfacialtension between the water and hydrocarbons.

Production from a hydrocarbon-bearing formation may be enhanced bytreating the hydrocarbon-bearing formation with a polymer and/or monomerthat may mobilize hydrocarbons to one or more production wells. Thepolymer and/or monomer may reduce the mobility of the water phase inpores of the hydrocarbon-bearing formation. The reduction of watermobility may allow the hydrocarbons to be more easily mobilized throughthe hydrocarbon-bearing formation. Polymers include, but are not limitedto, polyacrylamides, partially hydrolyzed polyacrylamide, polyacrylates,ethylenic copolymers, biopolymers, carboxymethylcellulose, polyvinylalcohol, polystyrene sulfonates, polyvinylpyrrolidone, AMPS(2-acrylamide-2-methyl propane sulfonate) or combinations and ormodifications thereof. Examples of ethylenic copolymers includecopolymers of acrylic acid and acrylamide, acrylic acid and laurylacrylate, lauryl acrylate and acrylamide. Examples of biopolymersinclude xanthan gum and guar gum. In some embodiments, polymers may becross linked in situ in a hydrocarbon-bearing formation. In otherembodiments, polymers may be generated in situ in a hydrocarbon-bearingformation. Polymers and polymer preparations for use in oil recovery aredescribed in U.S. Pat. No. 6,427,268 to Zhang et al., entitled “MethodFor Making Hydrophobically Associative Polymers, Methods of Use andCompositions;” U.S. Pat. No. 6,439,308 to Wang, entitled “Foam DriveMethod;” U.S. Pat. No. 5,654,261 to Smith, entitled, “PermeabilityModifying Composition For Use In Oil Recovery;” U.S. Pat. No. 5,284,206to Surles et al., entitled “Formation Treating;” U.S. Pat. No. 5,199,490to Surles et al., entitled “Formation Treating” and U.S. Pat. No.5,103,909 to Morgenthaler et al., entitled “Profile Control In EnhancedOil Recovery,” all of which are incorporated by reference herein.

The Hydrocarbon Recovery Composition

In an embodiment, a hydrocarbon recovery composition may be provided tothe hydrocarbon-bearing formation. In this invention the compositioncomprises a particular internal olefin sulfonate or blend of internalolefin sulfonates. Internal olefin sulfonates are chemically suitablefor EOR because they have a low tendency to form orderedstructures/liquid crystals (which can be a major issue because orderedstructures tend to lead to plugging of the rock structure in hydrocarbonformations, and possible emulsion formation) because they are a complexmixture of surfactants of with different chain lengths. Internal olefinsulfonates show a low tendency to adsorb on reservoir rock surfacesarising from negative-negative charge repulsion between the surface andthe surfactant. The use of alkali further reduces the tendency forsurfactants to adsorb and reduced losses means a lower concentration ofthe surfactant can be used making the process more economic. Howeverthis may also lead to emulsion stabilization due to the presence ofnatural surfactants present in the crude oil (e.g., naphthenic acids).Therefore, selection of crude oils for this chemical EOR method must bedone with caution. Moreover, injection of alkali may lead to formationdamage in particular mineralogy.

As discussed above in detail, this invention is particularly useful inhydrocarbon-bearing formations which contain crude oil with particularcomposition (e.g. solubility groups and specific chemical families). Thehydrocarbon recovery composition of this invention is designed toproduce the best internal olefin sulfonate recovery composition forthese hydrocarbon-bearing formations and for the brine found in theseformations. The preferred composition comprises a C₂₄₋₂₈ internal olefinsulfonate.

An internal olefin is an olefin whose double bond is located anywherealong the carbon chain except at a terminal carbon atom. A linearinternal olefin does not have any alkyl, aryl, or alicyclic branching onany of the double bond carbon atoms or on any carbon atoms adjacent tothe double bond carbon atoms. Typical commercial products produced byisomerization of alpha olefins are predominantly linear and contain alow average number of branches per molecule.

In an embodiment, the hydrocarbon recovery composition may comprise fromabout 1 to about 75 wt % of the C₂₄₋₂₈ internal olefin sulfonate orblend containing it, preferably from about 10 to about 40 wt % and morepreferably from about 20 to about 30 wt %. In an embodiment, ahydrocarbon containing composition may be produced from ahydrocarbon-bearing formation. The hydrocarbon-bearing composition mayinclude any combination of hydrocarbons, the internal olefin sulfonatedescribed above, a solubilizing agent, gas, water, crude oil solubilitygroups (e.g., asphaltenes, resins), specific chemical families (e.g.,naphthenic acids, basic nitrogen compounds).

The remainder of the composition may include, but is not limited to,water, low molecular weight alcohols, organic solvents, alkylsulfonates, aryl sulfonates, brine or combinations thereof. Lowmolecular weight alcohols include, but are not limited to, methanol,ethanol, propanol, isopropyl alcohol, tert-butyl alcohol, sec-butylalcohol, butyl alcohol, tert-amyl alcohol or combinations thereof.Organic solvents include, but are not limited to, methyl ethyl ketone,acetone, lower alkyl cellosolves, lower alkyl carbitols or combinationsthereof.

Manufacture of the Hydrocarbon Recovery Composition

The internal olefins that are used to make the internal olefinsulfonates of the present invention may be made by skeletalisomerization. Suitable processes for making the internal olefinsinclude those described in U.S. Pat. Nos. 5,510,306, 5,633,422,5,648,584, 5,648,585, 5,849,960, and European Patent EP 0,830,315 B1,all of which are herein incorporated by reference in their entirety. Ahydrocarbon stream comprising at least one linear olefin is contactedwith a suitable catalyst, such as the catalytic zeolites described inthe aforementioned patents, in a vapor phase at a suitable reactiontemperature, pressure, and space velocity. Generally, suitable reactionconditions include a temperature of about 200 to about 650° C., anolefin partial pressure of above about 0.5 atmosphere, and a totalpressure of about 0.5 to about 10.0 atmospheres or higher. Preferably,the internal olefins of the present invention are made at a temperaturein the range of from about 200 to about 500° C. at an olefin partialpressure of from about 0.5 to 2 atmospheres.

It is generally known that internal olefins are more difficult tosulfonate than alpha olefins (see “Tenside Detergents” 22 (1985) 4, pp.193-195). In the article entitled “Why Internal Olefins are Difficult toSulfonate,” the authors state that by the sulfonation of variouscommercial and laboratory produced internal olefins using falling filmreactors, internal olefins gave conversions of below 90 percent andfurther they state that it was found necessary to raise the SO₃:internalolefin mole ratio to over 1.6:1 in order to achieve conversions above 95percent. Furthermore, there resulting products were very dark in colorand had high levels of di- and poly-sulfonated products.

U.S. Pat. Nos. 4,183,867 and 4,248,793, which are herein incorporated byreference, disclose processes which can be used to make the branchedinternal olefin sulfonates of the invention. They are carried out in afalling film reactor for the preparation of light color internal olefinsulfonates. The amounts of unreacted internal olefins are between 10 and20 percent and at least 20 percent, respectively, in the processes andspecial measures must be taken to remove the unreacted internal olefins.The internal olefin sulfonates containing between 10 and 20 percent andat least 20 percent, respectively, of unreacted internal olefins must bepurified before being used. Consequently, the preparation of internalolefin sulfonates having the desired light color and with the desiredlow free oil content offer substantial difficulty.

Such difficulties can be avoided by following the process disclosed inEuropean Patent EP 0,351,928 B1, which is herein incorporated byreference.

A process which can be used to make internal olefin sulfonates for usein the present invention comprises reacting in a film reactor aninternal olefin as described above with a sulfonating agent in a moleratio of sulfonating agent to internal olefin of 1:1 to 1.25:1 whilecooling the reactor with a cooling means having a temperature notexceeding 35° C., directly neutralizing the obtained reaction product ofthe sulfonating step and, without extracting the unreacted internalolefin, hydrolyzing the neutralized reaction product.

In the preparation of the sulfonates derived from internal olefins, theinternal olefins are reacted with a sulfonating agent, which may besulfur trioxide, sulfuric acid, or oleum, with the formation ofbeta-sultone and some alkane sulfonic acids. The film reactor ispreferably a falling film reactor.

The reaction products are neutralized and hydrolyzed. Under certaincircumstances, for instance, aging, the beta-sultones are converted intogamma-sultones which may be converted into delta-sultones. Afterneutralization and hydrolysis, gamma-hydroxy sulfonates anddelta-hydroxy sulfonates are obtained. A disadvantage of these twosultones is that they are more difficult to hydrolyze thanbeta-sultones. Thus, in most embodiments it is preferable to proceedwithout aging. The beta sultones, after hydrolysis, give beta-hydroxysulfonates. These materials do not have to be removed because they formuseful surfactant structures.

The cooling means, which is preferably water, has a temperature notexceeding 35° C., especially a temperature in the range of from 0 to 25°C. Depending upon the circumstances, lower temperatures may be used aswell.

The reaction mixture is then fed to a neutralization hydrolysis unit.The neutralization/hydrolysis is carried out with a water soluble base,such as sodium hydroxide or sodium carbonate. The corresponding basesderived from potassium or ammonium are also suitable. The neutralizationof the reaction product from the falling film reactor is generallycarried out with excessive base, calculated on the acid component.Generally, neutralization is carried out at a temperature in the rangeof from 0 to 80° C. Hydrolysis may be carried out at a temperature inthe range of from 100 to 250° C., preferably 130 to 200° C. Thehydrolysis time generally may be from 5 minutes to 4 hours. Alkalinehydrolysis may be carried out with hydroxides, carbonates, bicarbonatesof (earth) alkali metals, and amine compounds.

This process may be carried out batchwise, semi-continuously, orcontinuously. The reaction is generally performed in a falling filmreactor which is cooled by flowing a cooling means at the outside wallsof the reactor. At the inner walls of the reactor, the internal olefinflows in a downward direction. Sulfur trioxide is diluted with a streamof nitrogen, air, or any other inert gas into the reactor. Theconcentration of sulfur trioxide generally is between 2 and 5 percent byvolume based on the volume of the carrier gas. In the preparation ofinternal olefin sulfonates derived from the olefins of the presentinvention, it is required that in the neutralization hydrolysis stepvery intimate mixing of the reactor product and the aqueous base isachieved. This can be done, for example, by efficient stirring or theaddition of a polar cosolvent (such as a lower alcohol) or by theaddition of a phase transfer agent.

Injection of the Hydrocarbon Recovery Composition

The hydrocarbon recovery composition may interact with hydrocarbons inat least a portion of the hydrocarbon containing formation. Interactionwith the hydrocarbons may reduce an interfacial tension of thehydrocarbons with one or more fluids in the hydrocarbon-bearingformation. In other embodiments, a hydrocarbon recovery composition mayreduce the interfacial tension between the hydrocarbons and anoverburden/underburden of a hydrocarbon-bearing formation. Reduction ofthe interfacial tension may allow at least a portion of the hydrocarbonsto mobilize through the hydrocarbon-bearing formation.

The ability of a hydrocarbon recovery composition to reduce theinterfacial tension of a mixture of hydrocarbons and fluids may beevaluated using known techniques. In an embodiment, an interfacialtension value for a mixture of hydrocarbons and water may be determinedusing a spinning drop tensionmeter. This is carried out under controlledlaboratory conditions, so it is only an approximation of reservoirconditions. An amount of the hydrocarbon recovery composition may beadded to the hydrocarbon/water mixture and an interfacial tension valuefor the resulting fluid may be determined. A low interfacial tensionvalue (e.g., less than about 1 dyne/cm) may indicate that thecomposition reduced at least a portion of the surface energy between thehydrocarbons and water. Reduction of surface energy may indicate that atleast a portion of the hydrocarbon/water mixture may mobilize through atleast a portion of a hydrocarbon-bearing formation.

In an embodiment, a hydrocarbon recovery composition may be added to ahydrocarbon/water mixture and the interfacial tension value may bedetermined. Preferably, the interfacial tension is less than about 0.1dyne/cm. An ultralow interfacial tension value (e.g., less than about0.01 dyne/cm) may indicate that the hydrocarbon recovery compositionlowered at least a portion of the surface tension between thehydrocarbons and water such that at least a portion of the hydrocarbonsmay mobilize through at least a portion of the hydrocarbon-bearingformation. At least a portion of the hydrocarbons may mobilize moreeasily through at least a portion of the hydrocarbon-bearing formationat an ultra low interfacial tension than hydrocarbons that have beentreated with a composition that results in an interfacial tension valuegreater than 0.01 dynes/cm for the fluids in the formation. Addition ofa hydrocarbon recovery composition to fluids in a hydrocarbon-bearingformation that results in an ultra-low interfacial tension value mayincrease the efficiency at which hydrocarbons may be produced. Ahydrocarbon recovery composition concentration in the hydrocarboncontaining formation may be minimized to minimize cost of use duringproduction.

In an embodiment of a method to treat a hydrocarbon-bearing formation, ahydrocarbon recovery composition including an internal olefin sulfonatemay be provided (e.g., injected) into hydrocarbon-bearing formation 100through injection well 110 as depicted in FIG. 1. Hydrocarbon formation100 may include overburden 120, hydrocarbon layer 130, and underburden140. Injection well 110 may include openings 112 that allow fluids toflow through hydrocarbon containing formation 100 at various depthlevels. In certain embodiments, hydrocarbon layer 130 may be less than1000 feet below earth's surface. In some embodiments, underburden 140 ofhydrocarbon containing formation 100 may be oil wet. Low salinity watermay be present in hydrocarbon containing formation 100, in otherembodiments.

A hydrocarbon recovery composition may be provided to the formation inan amount based on hydrocarbons present in a hydrocarbon-bearingformation. The amount of hydrocarbon recovery composition, however, maybe too small to be accurately delivered to the hydrocarbon-bearingformation using known delivery techniques (e.g., pumps). To facilitatedelivery of small amounts of the hydrocarbon recovery composition to thehydrocarbon-bearing formation, the hydrocarbon recovery composition maybe combined with water and/or brine to produce an injectable fluid.

In an embodiment, the hydrocarbon recovery composition is provided tothe formation containing crude oil with heavy components by admixing itwith brine from the formation from which hydrocarbons are to beextracted or with fresh water. The mixture is then injected into thehydrocarbon-bearing formation.

In an embodiment, the hydrocarbon recovery composition is provided to ahydrocarbon-bearing formation 100 by admixing it with brine from theformation. Preferably, the hydrocarbon recovery composition comprisesfrom about 0.01 to about 2.00 wt % of the total water and/orbrine/hydrocarbon recovery composition mixture (the injectable fluid).More important is the amount of actual active matter that is present inthe injectable fluid (active matter is the surfactant, here the C₂₄₋₂₈internal olefin sulfonate or the blend containing it). Thus, the amountof the internal olefin sulfonate in the injectable fluid may be fromabout 0.05 to about 1.0 wt %, preferably from about 0.1 to about 0.8 wt%. More than 1.0 wt % could be used but this would likely increase thecost without enhancing the performance. The injectable fluid is theninjected into the hydrocarbon-bearing formation.

C₁₅₋₁₈ internal olefin sulfonates, C₁₉₋₂₃ internal olefin sulfonates,C₂₀₋₂₄ internal olefin sulfonates and mixtures thereof may be blendedwith the C₂₄₋₂₈ internal olefin sulfonate to enhance its microemulsionbehavior. The weight ratio of the C₂₄₋₂₈ internal olefin sulfonate tothe other IOS may be from about 10:90 to about 90:10. Preferably theC₂₄₋₂₈ internal olefin sulfonate comprises at least about 50% by weightof the IOS blend.

The C24-28 internal olefin sulfonate may be used without a co-surfactantand/or a solvent. The C₂₄₋₂₈ internal olefin sulfonate may not performoptimally by itself for certain crude oils. This is a result of theoverall crude oil composition. Co-surfactants and/or co-solvents may beadded to the hydrocarbon recovery composition to enhance the activity.In one embodiment, the hydrocarbon recovery composition comprised C₂₄₋₂₈internal olefin sulfonate, C₁₅₋₁₈ internal olefin sulfonate and2-butanol.

The hydrocarbon recovery composition may interact with at least aportion of the hydrocarbons in hydrocarbon layer 130. The interaction ofthe hydrocarbon recovery composition with hydrocarbon layer 130 mayreduce at least a portion of the interfacial tension between differenthydrocarbons. The hydrocarbon recovery composition may also reduce atleast a portion of the interfacial tension between one or more fluids(e.g., water, hydrocarbons) in the formation and the underburden 140,one or more fluids in the formation and the overburden 120 orcombinations thereof.

In an embodiment, a hydrocarbon recovery composition may interact withat least a portion of hydrocarbons and at least a portion of one or moreother fluids in the formation to reduce at least a portion of theinterfacial tension between the hydrocarbons and one or more fluids.Reduction of the interfacial tension may allow at least a portion of thehydrocarbons to form an emulsion with at least a portion of one or morefluids in the formation. An interfacial tension value between thehydrocarbons and one or more fluids may be altered by the hydrocarbonrecovery composition to a value of less than about 0.1 dyne/cm. In someembodiments, an interfacial tension value between the hydrocarbons andother fluids in a formation may be reduced by the hydrocarbon recoverycomposition to be less than about 0.05 dyne/cm. An interfacial tensionvalue between hydrocarbons and other fluids in a formation may belowered by the hydrocarbon recovery composition to less than 0.001dyne/cm, in other embodiments.

At least a portion of the hydrocarbon recoverycomposition/hydrocarbon/fluids mixture may be mobilized to productionwell 150. Products obtained from the production well 150 may include,but are not limited to, components of the hydrocarbon recoverycomposition (e.g., a long chain aliphatic alcohol and/or a long chainaliphatic acid salt), gas, water, hydrocarbons, solubility groups (e.g.,asphaltenes, resins) and/or chemical families (naphthenic acids, basicnitrogen), or combinations thereof. Hydrocarbon production fromhydrocarbon-bearing formation 100 may be increased by greater than about50% after the hydrocarbon recovery composition has been added to ahydrocarbon-bearing formation.

In certain embodiments, hydrocarbon-bearing formation 100 may bepretreated with a hydrocarbon removal fluid. A hydrocarbon removal fluidmay be composed of water, steam, brine, gas, liquid polymers, foampolymers, monomers or mixtures thereof. A hydrocarbon removal fluid maybe used to treat a formation before a hydrocarbon recovery compositionis provided to the formation. Hydrocarbon-bearing formation 100 may beless than 1000 feet below the earth's surface, in some embodiments. Ahydrocarbon removal fluid may be heated before injection into ahydrocarbon-bearing formation 100, in certain embodiments. A hydrocarbonremoval fluid may reduce a viscosity of at least a portion of thehydrocarbons within the formation. Reduction of the viscosity of atleast a portion of the hydrocarbons in the formation may enhancemobilization of at least a portion of the hydrocarbons to productionwell 150. After at least a portion of the hydrocarbons inhydrocarbon-bearing formation 100 have been mobilized, repeatedinjection of the same or different hydrocarbon removal fluids may becomeless effective in mobilizing hydrocarbons through thehydrocarbon-bearing formation. Low efficiency of mobilization may be dueto hydrocarbon removal fluids creating more permeable zones inhydrocarbon-bearing formation 100. Hydrocarbon removal fluids may passthrough the permeable zones in the hydrocarbon-bearing formation 100 andnot interact with and mobilize the remaining hydrocarbons. Consequently,displacement of heavier hydrocarbons adsorbed to underburden 140 may bereduced over time. Eventually, the formation may be considered lowproducing or economically undesirable to produce hydrocarbons.

In certain embodiments, injection of a hydrocarbon recovery compositionafter treating the hydrocarbon containing formation with a hydrocarbonremoval fluid may enhance mobilization of heavier hydrocarbons absorbedto underburden 140. The hydrocarbon recovery composition may interactwith the hydrocarbons to reduce an interfacial tension between thehydrocarbons and underburden 140. Reduction of the interfacial tensionmay be such that hydrocarbons are mobilized to and produced fromproduction well 150. Produced hydrocarbons from production well 150 mayinclude, in some embodiments, at least a portion of the components ofthe hydrocarbon recovery composition, the hydrocarbon removal fluidinjected into the well for pretreatment, methane, carbon dioxide,ammonia, or combinations thereof. Adding the hydrocarbon recoverycomposition to at least a portion of a low producing hydrocarbon-bearingformation may extend the production life of the hydrocarbon-bearingformation. Hydrocarbon production from hydrocarbon-bearing formation 100may be increased by greater than about 50% after the hydrocarbonrecovery composition has been added to hydrocarbon-bearing formation.Increased hydrocarbon production may increase the economic viability ofthe hydrocarbon-bearing formation.

Interaction of the hydrocarbon recovery composition with at least aportion of hydrocarbons in the formation may reduce at least a portionof an interfacial tension between the hydrocarbons and underburden 140.Reduction of at least a portion of the interfacial tension may mobilizeat least a portion of hydrocarbons through hydrocarbon-bearing formation100. Mobilization of at least a portion of hydrocarbons, however, maynot be at an economically viable rate.

In one embodiment, polymers and/or monomers may be injected intohydrocarbon formation 100 through injection well 110, after treatment ofthe formation with a hydrocarbon recovery composition, to increasemobilization of at least a portion of the hydrocarbons through theformation. Suitable polymers include, but are not limited to, CIBA®ALCOFLOOD®, manufactured by Ciba Specialty Additives (Tarrytown, N.Y.),Tramfloc® manufactured by Tramfloc Inc. (Temple, Ariz.), and HE®polymers manufactured by Chevron Phillips Chemical Co. (The Woodlands,Tex.). Interaction between the hydrocarbons, the hydrocarbon recoverycomposition and the polymer may increase mobilization of at least aportion of the hydrocarbons remaining in the formation to productionwell 150.

The internal olefin sulfonate of the composition is thermally stable andmay be used over a wide range of temperatures. The hydrocarbon recoverycomposition may be added to a portion of a hydrocarbon-bearing formation100 that has an average temperature of above about 70° C. because of thehigh thermal stability of the internal olefin sulfonate.

In some embodiments, a hydrocarbon recovery composition may be combinedwith at least a portion of a hydrocarbon removal fluid (e.g. water,polymer solutions) to produce an injectable fluid. The hydrocarbonrecovery composition may be injected into hydrocarbon-bearing formation100 through injection well 110 as depicted in FIG. 2. Interaction of thehydrocarbon recovery composition with hydrocarbons in the formation mayreduce at least a portion of an interfacial tension between thehydrocarbons and underburden 140. Reduction of at least a portion of theinterfacial tension may mobilize at least a portion of hydrocarbons to aselected section 160 in hydrocarbon-bearing formation 100 to formhydrocarbon pool 170. At least a portion of the hydrocarbons may beproduced from hydrocarbon pool 170 in the selected section ofhydrocarbon-bearing formation 100.

In other embodiments, mobilization of at least a portion of hydrocarbonsto selected section 160 may not be at an economically viable rate.Polymers may be injected into hydrocarbon formation 100 to increasemobilization of at least a portion of the hydrocarbons through theformation. Interaction between at least a portion of the hydrocarbons,the hydrocarbon recovery composition and the polymers may increasemobilization of at least a portion of the hydrocarbons to productionwell 150.

In some embodiments, a hydrocarbon recovery composition may include aninorganic salt (e.g. sodium carbonate (Na₂CO₃), sodium hydroxide, sodiumchloride (NaCl), or calcium chloride (CaCl₂)). The addition of theinorganic salt may help the hydrocarbon recovery composition dispersethroughout a hydrocarbon/water mixture. The enhanced dispersion of thehydrocarbon recovery composition may decrease the interactions betweenthe hydrocarbon and water interface. Addition of different salts willaffect the final IFT of the system. The use of an alkali (e.g., sodiumcarbonate, sodium hydroxide) may prevent adsorption of the IOS onto therock surface and may create natural surfactants with components in thecrude oil. The decreased interaction may lower the interfacial tensionof the mixture and provide a fluid that is more mobile. The alkali maybe added in an amount of from about 0.1 to 2.0 wt %.

Under the temperature and pressure conditions in the reservoir, theC₂₄₋₂₈ internal olefin sulfonate is soluble and is effective in loweringthe IFT. However, conditions above ground where the injectable fluidcomposition is prepared are different, i.e., lower temperature andpressure. Under such conditions and in a low salinity brine orfreshwater (no salinity), the C₂₄₋₂₈ internal olefin sulfonate may notbe completely soluble. Before the injectable fluid can be injected, atleast a significant portion of the C₂₄₋₂₈ internal olefin sulfonatefalls out of the mixture. Any portion of the surfactant that is not insolution, i.e. that remains insoluble and forms a waxy precipitate, willeventually plug the porous formation around the wellbore. The resultwill be that the injection well will plug, with the consequent loss ofthe ability to inject the fluid. Remedial treatments will have to bedone to the well to put it back in function with the consequent loss oftime and expense. It would be advantageous if a means were found to keepthe C₂₄₋₂₈ internal olefin sulfonate in solution in the injectable fluidas it is injected.

The invention provides a method of injecting a hydrocarbon recoverycomposition comprising a C₂₄₋₂₈ internal olefin sulfonate into ahydrocarbon containing formation which comprises: (a) making asolubilized C₂₄₋₂₈ internal olefin sulfonate hydrocarbon recoverycomposition fluid by mixing a major portion of a C₂₄₋₂₈ internal olefinsulfonate in fresh water or water having a brine salinity of less thanabout 2 wt % at a temperature of 50° C. or lower and adding to themixture a minor amount of a solubilizer which comprises a C₁₅₋₁₈internal olefin sulfonate or a C₁₉₋₂₃ internal olefin sulfonate ormixtures thereof; and (b) injecting the solubilized C₂₄₋₂₈ internalolefin sulfonate hydrocarbon recovery composition into the hydrocarboncontaining formation. The weight ratio of the solubilizer to the C₂₄₋₂₈internal olefin sulfonate may be from about 10:90 to about 90:10.

EXAMPLES Example 1

A hydrocarbon recovery composition including a C₂₄₋₂₈ internal olefinsulfonate (IOS) was prepared and microemulsion tests with crude oil werecompared for two crude oils with higher amounts of specific solubilitygroups and chemical families and two crude oils with lower amounts ofspecific solubility groups and chemical families. The internal olefinsulfonate was tested as described below.

The C₂₄₋₂₈ internal olefins were a mixture of odd and even carbon numberolefins and had an average carbon number of 26. The C23 olefin was 7% ofthe total, C24 was 9%, C25 was 10%, C26 was 11%, C27 was 10%, C28 was10% and C29 was 8%. 50% of the internal olefins had from 24 to 28 carbonatoms.

The C₁₅₋₁₈ internal olefins were a mixture of odd and even carbon numberolefins and had an average carbon number of 16.3. The C14 olefin was 1%of the total, C15 was 25%, C16 was 27%, C17 was 27%, C18 was 20% and C19was <1%. 96% of the internal olefins had from 15 to 18 carbon atoms.

Oil solubilization at the optimal salinity of the surfactant is measuredby microemulsion tests with no indication of undesirable viscous phasesand is an important criterion for the effectiveness of a surfactant forenhanced oil recovery. Oil solubilization is defined by solubilizationratio or solubilization parameter and is the ratio of oil to surfactant(and water to surfactant) in a middle phase Winsor Type IIImicroemulsion. It can also be judged in tests with crude oils by theformation of lighter brown, creamy microemulsions for oil/watermixtures, such microemulsions being associated with “high activity”which generally translates into low interfacial tension.

A C₂₄₋₂₈ internal olefin sulfonate (IOS) was found to give high activityin microemulsion tests with no indication of undesirable viscous phasesfor crude oils containing higher asphaltene to resin ratios, as well aslower saturate to aromatic ratios. The crude oils which did not performwell in these tests also contain high concentrations of naphthenicacids. It is theorized that these chemical families were responsible forthe appearance of macro-emulsion phases. Although termed C₂₄₋₂₈ IOS,this product contains molecules with a wide range of carbon numbers andthis includes up to C₃₆. It is theorized that the heavier C₂₄₋₂₈ IOScomponents are able to match up with the specific solubility group andchemical family crude oil components. Other IOSs with lower carbonnumbers do not show this behavior.

Microemulsion tests with IOS-only formulations containing C₂₄₋₂₈ IOS asthe primary surfactant component have been carried out with severalcrude oils and at different temperature and salinity conditions. Glasssample tubes containing oil, aqueous IOS solution and air wereequilibrated at the test temperature with periodic shaking. Testtemperatures were in the range 54-90° C. and an “effective saltconcentration” of 1-4% wt (“effective salt concentration” meaning thetotal of NaCl [or KCl] and Na₂CO₃ concentrations). Based on other tests,the effective temperature range of the IOS family is 40-140° C. sincethe IOS family is temperature stable to the highest practicaltemperatures for EOR.

In addition, the optimal salinity (the salinity at which equal volumesof brine and oil are solubilized in the middle-phase microemulsion;also, the salinity where highest activity is measured) of IOSformulations containing C₂₄₋₂₈ IOS shows relatively small changes withtemperature. This is a potential benefit for reservoirs with areas ofdifferent temperature regions where only slight adjustments to theformulation should be required.

Microemulsions tests with a C₂₄₋₂₈ IOS formulation and a crude oil witha high asphaltene to resin ratio were carried out to test for optimalsalinity. The tests were carried out at 60° C. The initial volumes were30% v oil and 70% v aqueous solution (of brine+IOS surfactant+polymer).

At 0.5% wt KCl, the system was 2-phase and “under-optimum”. Almost allof the surfactant was in the brine phase. At 0.75% wt KCl, more oil wassolubilized in the brine phase and a third micro-emulsion phase startedto develop at the oil-brine interface. At 1.25% wt KCl, themicro-emulsion volume was maximum and the system was at optimumconditions. This defines the optimal salinity for this system. Theemulsion was a pale-brown color which is a good indication of a veryactive system with an ultra-low IFT. The brine phase was almost clearbecause most surfactant was then present in the micro-emulsion phase.The IFT should be at a minimum at this salt concentration. At 1.5% wtKCl the system was “over-optimum”. All of the surfactant was in the oilphase.

Other tests with model oils showed that C₂₄₋₂₈ IOS gave very high oilsolubilization with dodecane compared with octane, indicating the longercarbon chains of the surfactant are more effectively solvated by theheavier model oil, this being consistent with the result of theparaffinic crude.

Five crude oils with different concentrations of specific solubilitygroups and chemical families were tested for surfactant activity inphase behavior tests. These tests were carried out as described above.The results are shown in Table 1 below. FIG. 3 shows the effect of crudeoil solubility fractions on IOS performance.

All of the crude oils were “light oils” according to the API gravityclassification. Crude oils A and B had low asphaltene to resin ratio,high saturate to aromatic ratio and high naphthenic acid concentrationwhile oils C and D had high asphaltene to resin ratio, low saturate toaromatic ratio and low naphthenic acid concentration. The surfactantsystem was a mixture of 0.5% wt C₂₄₋₂₈ IOS+0.2% wt C₁₅₋₁₈ IOS+1% wt2-butanol.

TABLE 1 Oil Composition (wt %) Optimal salinity Crude API TAN S A R AsNA (ppm) (% m KCl) C₂₄₋₂₈ Surfactant Activity A 38.1 0.14 59.2 33.0 7.60.2 3230 0.5 activity seen but with viscous B 33.1 0.19 44.4 44.8 10.50.2 3360 0.8 phases, C₂₄₋₂₈ IOS poorly compatible with oil C 31.3 0.0428.6 53.9 12.2 5.3 1500 1.3 excellent activity D 37.3 0.03 34.1 49.314.9 1.7 1856 1.2 E 26.5 0.07 27.5 52.3 13.6 6.6 n.m. 1.3 n.m. = notmeasured

It is clear from these results that the C₂₄₋₂₈ IOS surfactant is lesscompatible with the crude oils with lower asphaltene to resin ratios,higher saturate to aromatic ratios and higher naphthenic acidconcentration and is more compatible with the crude oils with higherasphaltene to resin ratios, lower saturate to aromatic ratios and lowernaphthenic acid concentration.

Example 2

Aqueous solubility tests of C₂₄₋₂₈ internal olefins at ambienttemperature (0.7% wt active concentration of the surfactant inde-ionized water) showed that the solution was hazy with undissolvedsolids. Above 50° C. all solids were dissolved, although the micellarsolution was still hazy. The same test with C₂₄₋₂₈ internal olefinsblended with C₁₅₋₁₈ internal olefins in a weight ratio 0.5/0.2 gave anearly clear and homogeneous solution and no undissolved solids at atemperature of 60° C. and above. The presence of co-solvent such assec-butyl alcohol was found to further improve aqueous solubility andmicroemulsion behavior.

The microemulsion activity of C₂₄₋₂₈ internal olefins alone and blendedwith C₁₅₋₁₈ internal olefins in a weight ratio 0.7/0.1 was determined at85° C. The blends contained 1% wt 2-butanol and were added to a 70/30%wt brine/oil mixture. The C₂₄₋₂₈ internal olefins alone showedreasonable activity—a microemulsion formed at the oil/brine surface. Thesolubilization parameter at optimal salinity (0.75% wt NaCl and 1% wtNa₂CO₃) was 4. The C₂₄₋₂₈ IOS blend with C₁₅₋₁₈ IOS showed excellentactivity—a relatively large microemulsion volume was formed. Thesolubilization parameter at optimal salinity (2% wt NaCl and 1% wtNa₂CO₃) was 15. Thus, the surfactant activity was also improved byadding the C₁₅₋₁₈ IOS.

Hydrocarbon recovery compositions including a C₂₀₋₂₄ internal olefinsulfonate and lower carbon number IOS were prepared and microemulsiontests were compared for the different compositions.

The C₂₀₋₂₄ internal olefins (made from alpha olefins) were a mixture ofonly even carbon number olefins and had an average carbon number of20.7. 4-5% of the total olefins were C18 internal olefins (18 carbonatoms), 59-61% were C20, 29-31% were C22 and 3-8% were C24. 92% of theinternal olefins had from 20 to 24 carbon atoms. It was made with a highSO₃/olefin ratio.

The C₁₉₋₂₃ internal olefins (made from alpha olefins) were a mixture ofonly even carbon number olefins and had an average carbon number of 22.3% of the total olefins were C18 internal olefins or lower (18 or lesscarbon atoms), 13% were C19, 15% were C20, 14% were C21, 13% were C22,11% were C23 and 31% were C24 internal olefins or higher. 66% of theinternal olefins had from 19 to 23 carbon atoms.

The C₂₄₋₂₈ internal olefins alone gave lower microemulsion activity thana blend of C₂₄₋₂₈ internal olefins with C₁₅₋₁₈ internal olefins. Forexample in a test with 0.7% C₂₄₋₂₈ IOS, the oil and water volatilizationat optimum salinity was 4. The same test with a 0.7/0.1% wtC₂₄₋₂₈/C₁₅₋₁₈ IOS surfactant mixture resulted in a solubilization of 15.

Use of C₂₀₋₂₄ internal olefins mixed as a secondary component withC₂₄₋₂₈ IOS was found to give improved microemulsion behavior but notimproved aqueous solubility. The C₁₉₋₂₃ IOS also gave improvedmicroemulsion behavior (aqueous solubility was not determined). However,the C₁₉₋₂₃ IOS, due to its branching and wide carbon numberdistribution, is expected to improve aqueous solubility as well.

Example 3

The C₂₄₋₂₈ internal olefin sulfonates were tested with alkanes and acrude oil without co-surfactants to further study their behavior. Theinternal olefin sulfonates were tested at 90° C. for n-octane andn-dodecane; and at 54° C. for the crude oil test. The results of thesetests are shown in Table 2.

TABLE 2 Surfactant Oil Activity Comments C₂₄₋₂₈ IOS n-octane High 2%active surfactant, no solvent C₂₄₋₂₈ IOS n-dodecane High 2% activesurfactant, no solvent C₂₄₋₂₈ IOS Crude F Low 0.3% active surfactant, 1%DGBE

The results show that the long-tailed C₂₄₋₂₈ internal olefin sulfonatehas excellent performance with alkanes in the absence of aco-surfactant/solvent. On the other hand, the tests with crude F showthat C₂₄₋₂₈ internal olefin sulfonates are more efficient when used witha solvent and/or co-surfactant.

What is claimed is:
 1. A hydrocarbon recovery composition whichcomprises a first blend of C24-28 internal olefin sulfonates and anotherinternal olefin sulfonate selected from the group consisting of C15-18internal olefin sulfonates, C19-23 internal olefin sulfonates, C20-24internal olefin sulfonates and mixtures thereof which are blended withthe C24-28 internal olefin sulfonate, and wherein the weight ratio ofthe C24-28 internal olefin sulfonate to the other internal olefinsulfonates is from about 71:29 to about 90:10.
 2. The composition ofclaim 1 wherein the weight ratio of the C24-28 internal olefin sulfonateto the other internal olefin sulfonates is from about 87.5:12.5 to about90:10.
 3. The composition of claim 1 wherein the first blend has anaverage carbon number of from 24.5 to 27 and at least 40% by weight ofthe internal olefin sulfonates in the blend contain from 24 to 28 carbonatoms.
 4. The composition of claim 1 wherein the first blend has anaverage carbon number of from 24.5 to 27 and at least 50% by weight ofthe internal olefin sulfonates in the blend contain from 24 to 28 carbonatoms.
 5. The composition of claim 1 wherein the first blend has anaverage carbon number of from 24.5 to 27 and at least 60% by weight ofthe internal olefin sulfonates in the blend contain from 24 to 28 carbonatoms.
 6. The composition of claim 1 which also comprises an inorganicsalt.
 7. The composition of claim 6 wherein the inorganic salt isselected from the group consisting of sodium carbonate, sodiumhydroxide, sodium chloride and calcium chloride.
 8. The composition ofclaim 6 wherein the inorganic salt comprises alkali.
 9. The compositionof claim 8 wherein the alkali is added in an amount of from about 0.1 to2 wt %.
 10. The composition of claim 1 which also comprises aco-surfactant and/or a co-solvent.
 11. The composition of claim 10wherein the co-solvent comprises 2-butanol.
 12. The composition of claim1 which also comprises diethylene glycol monobutyl ether.
 13. Thecomposition of claim 12 wherein the diethylene glycol monobutyl ether ispresent in an amount of 1 wt %.
 14. The composition of claim 1 whichalso comprises another internal olefin sulfonate selected from the groupconsisting of a second internal olefin sulfonate blend having an averagecarbon number of from about 16 to about 17 and at least 50% by weight,preferably at least 75% by weight, most preferably at least 90% byweight, of the internal olefin sulfonates in the blend contain fromabout 15 to about 18 carbon atoms, a third internal olefin sulfonateblend having an average carbon number of from about 21 to about 23 andat least 50% by weight, preferably at least 60% by weight, of theinternal olefin sulfonates in the mixture contain from 19 to 23 carbonatoms, a fourth internal olefin sulfonate blend having an average carbonnumber of from about 20.5 to about 23 and at least 50% by weight,preferably at least about 65% by weight, most preferably at least about75% by weight, of the internal olefin sulfonates in the blend containfrom about 20 to about 24 carbon atoms and mixtures thereof which areblended with the first internal olefin sulfonate blend, and whereinpreferably the first internal olefin sulfonate blend comprises at leastabout 71% by weight of the total internal olefin sulfonates.
 15. Thecomposition of claim 14 which also comprises alkali in an amount of fromabout 0.1 to 2 wt %.
 16. An injectable fluid composition comprising thehydrocarbon recovery composition of claim 1, water and/or brine whereinthe hydrocarbon recovery composition is present in an amount of from0.05 to 1.0 wt % of the total injectable fluid composition.
 17. Theinjectable fluid composition of claim 16 wherein the hydrocarbonrecovery composition is present in an amount of from 0.1 to 0.8 wt % ofthe total injectable fluid composition.
 18. The injectable fluidcomposition of claim 16 wherein the water and/or brine has a salinity ofless than about 2 wt %.